In the oil well drilling industry, it is important to reduce the economic cost of drilling a wellbore in order to extract oil and gas from underground reservoirs. With underground resources becoming accessible at even greater depths, it becomes evermore important to identify the most efficient and effective drilling configuration to be used in order to drill through the intervening rock formation and access the underground reservoir.
The drilling environment is a complex environment to physically model and predict, and multiple constraints are placed, by the environmental conditions and the physical limits of the drilling system and its components, on the drilling system designer and drilling system operator. In the case of drilling system selection for a planned well drilling operation, this has led to a trial-and-error approach to selection optimization, based on data obtained from actual drilling operations conducted at a location offset from the planned well drilling operation. However, much of this selection optimization focuses on past performance values, even though the drilling conditions for the planned well drilling operation may not be identical, and on a perception of drilling system reliability that may not take into account all relevant factors determinative of the actual reliability of the different available candidate systems for the purposes of the planned well drilling operation.
One measure of the effectiveness of a drilling configuration is the absolute drilling performance which the drilling configuration can achieve through a particular section of formation. Drilling system design is typically concerned with optimizing the performance of a drilling system for drilling through a particular formation as economically as possible, which in most cases means drilling as quickly as possible (with the highest rate of penetration (ROP)) with the fewest number of changes of the bottom hole assembly (BHA). Of course, whenever the bottom hole assembly has to be changed, the existing bottom hole assembly and the entire drill string has to be tripped out of the wellbore being drilled, and a new bottom hole assembly and the same length of drill string has to be tripped back into the hole to recommence drilling. With ever deeper wells being drilled, this process takes correspondingly longer, with increasing attendant costs.
One reason for changing the bottom hole assembly is that one type of BHA may achieve a higher rate of penetration in one type of rock, or be cheaper, but will not achieve a sufficient rate of penetration or will quickly become worn in another type of formation, for which a different type or configuration of the BHA would obtain superior performance. Where changes in the formation rock types are identified and known in advance, a change of bottom hole assembly can be planned into the well drilling operation.
However, another cause of having to change the bottom hole assembly is where the BHA fails, in particular where a component of the BHA, such as the drill bit or an associated downhole tool becomes worn or damaged.
The amount of wear which a drill bit will suffer can be predicted with increasing accuracy, and can also be monitored in “real time” during drilling, for example by tracking the frequency response of the vibrations generated by the drill bit as it drills through rock. Nevertheless, drill bits can break or become worn more quickly than expected, and downhole tools can be damaged by vibrations and environmental conditions. For example, the teeth of a drill bit may become damaged and break through impacting against the formation.
Where the BHA fails in such a manner, it may become necessary not only to trip out the damaged BHA, but also to carry out a “fishing” operation to retrieve any damaged component of the BHA that has become detached and left at the bottom of the wellbore. This again adds to the time and cost of drilling the wellbore. Where the downhole tool becomes damaged, it will also likely be necessary to trip out the drill string and replace the damaged downhole tool, especially where the downhole tool is used to provide “look-ahead” or geo-positional information to help steer and position the bottom hole assembly.
Although such types of failure may be classified as unpredictable or random, it may be that, where the BHA has been designed to obtain a focused optimization of one property of the BHA for drilling under one specific set of expected drilling conditions, the chances of the BHA failing increase when the actual drilling conditions deviate away from the expected drilling conditions, or that the extent of the deviation from optimal which is required to induce such a failure decreases.
The same principle may apply not only to design and selection of the BHA, but to the drilling system as a whole, where the selection of the BHA and the choice of drilling control parameters has been subjected to focused optimization based on expected drilling conditions.
The principle may be described as “robustness”—whether the designed system will be robust to variations in operating conditions as these move away from the design point. Of course, during drilling operations there are continuously changing drilling conditions, due to changing characteristics of the rocks in the formation with depth. The drilling system operator also has a significant degree of freedom to alter the system control parameters. Again, the system control parameters are normally selected according to a drilling plan designed to optimize drilling performance as far as possible at each point along the wellbore, although without unnecessarily continuously varying selectable parameters, such as weight-on-bit (WOB), which in certain cases may not readily be varied without undesirably requiring drilling operations to stop. Additionally, actual drilling conditions may differ from the expected drilling conditions due to inherent inaccuracy in the measurement equipment and prediction methods used to determine the expected formation properties.
It would therefore be advantageous to be able to assess, and where possible to control or limit, the degree to which a drilling system is exposed to situations of high risk of failure.
It would furthermore be advantageous to be able to compare the expected response of different drilling systems in order to identify the relative risk of failure associated with each drilling system.
It may be advantageous to be able to compare values indicating the risk of failure and robustness to variations in operating conditions against expected performance when selecting between different available candidate drilling systems for drilling a planned wellbore.
It would be advantageous to permit a drilling system to be designed which optimizes or maintains a level of performance for the drilling system at the same time as reducing the risk of failure or keeping the risk of failure within acceptable levels. Likewise, it would be advantageous to be able to optimize drilling system performance whilst also optimizing or maintaining a required degree of robustness to variations in external drilling conditions.
In certain cases, it would be advantageous to be able to perform ongoing risk analyses during drilling operations, and to adjust a prior risk assessment when actual drilling conditions and drilling system performance have been measured against the expected drilling conditions and predicted drilling system performance.
It would be further advantageous to enable a well planning method able to identify difficult-to-drill sections of the wellbore. Such may permit the selection or design of a drilling system configuration, or a combination of drilling system configurations, as well as a plan of drilling control parameters, to arrive at a solution that is robust to variations in drilling conditions within the formation, and/or which has a reduced risk of failure.